Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. As a result, over the years well architecture has become more sophisticated where appropriate in order to help enhance access to underground hydrocarbon reserves. For example, as opposed to wells of limited depth, it is not uncommon to find hydrocarbon wells exceeding 30,000 feet in depth. Furthermore, as opposed to remaining entirely vertical, today's hydrocarbon wells often include deviated or horizontal sections aimed at targeting particular underground reserves.
While such well depths and architecture may increase the likelihood of accessing underground hydrocarbons, other challenges are presented in terms of well management and the maximization of hydrocarbon recovery from such wells. For example, during the life of a well, a variety of well access applications may be performed within the well with a host of different tools or measurement devices. However, providing downhole access to wells of such challenging architecture may require more than simply dropping a wireline cable into the well with the applicable tool located at the end thereof. Thus, coiled tubing is frequently employed to provide access to wells of such challenging architecture.
Coiled tubing operations are particularly adept at providing access to highly deviated or tortuous wells where gravity alone fails to provide access to all regions of the wells. During a coiled tubing operation, a spool of pipe (i.e., a coiled tubing) with a downhole tool at the end thereof is slowly straightened and forcibly pushed into the well. This may be achieved by running coiled tubing from the spool and through a gooseneck guide arm and injector which are positioned over the well at the oilfield. In this manner, forces necessary to drive the coiled tubing through the deviated well may be employed, thereby delivering the tool to a desired downhole location.
Applications which may be carried out via coiled tubing include perforating, isolating and others which may involve the use of a firing head. For example, in the specific case of perforating, a firing head may be employed to set off a perforating gun in order to form perforations into a formation surrounding a main bore of the well. Given the generally cable-free nature of the coiled tubing and the potential well depths involved, it may be advantageous to actuate such a firing head in a remote fashion. Generally, this is achieved by way of ball-drop technique, whereby a ball or other suitable projectile is introduced into the coiled tubing at the oilfield surface and allowed to migrate downhole to a ball seat at the firing head which ultimately triggers firing thereof.
The noted ball-drop technique may be a bit lacking in terms of speed and precision. That is to say, the time elapse between the introduction of the ball to the coiled tubing at surface and the actual triggering may be quite significant and variable. So for example, depending on the depths and flow rates involved, this time elapse may average 30 minutes, plus or minus several more minutes. Therefore, where a quicker or more accurate triggering technique is desired, the ball-drop technique may be replaced with a flow signature technique. That is, given an available fluid flow through the coiled tubing, the firing head may be equipped with a flow detector receptive to a flow signature generated at surface. For example, pump rates of between about ½ barrel per minute (BPM) and about 2 BPM may be dynamically employed to generate a signal recognizable by the firing head to achieve activation thereof. Further, with a column of fluid already flowing within the coiled tubing, no significant time elapse between signal generation at surface and downhole firing head triggering may result. Thus, a more timely and accurate activation may be achieved.
While potentially more timely and accurate, a flow directed activation of a firing head is primarily responsive to conventional liquid fluid flow. However, in many circumstances, the introduction of liquids into the well via the coiled tubing may present significant drawbacks. For example, in many environments coiled tubing fluid in the form of seawater is employed until such time as the well begins producing. Thereafter, the coiled tubing flow may consist of a more inert nitrogen or other gas so as to avoid killing or otherwise hampering well production.
Unfortunately however, employing a flow signature for firing head detection is generally unreliable where a conventional flow detector and gas flow are utilized. Therefore, a degree of time savings and accuracy are generally sacrificed where triggering of a firing head is sought in environments which are non-conducive to the introduction of fluid flow.